The invention relates to a method and a device for determination volume flow rates and volume concentrations of liquid phase components and gas in multiphase liquid/gas mixtures such as oil well fluids, composed of oil, water and gas. In particular the invention relates to such a method and such a device according to the preambles of claims 1 and 15 respectively.
An effluent flowing along a pipeline from an oil well is a multiphase mixture of oil, water and gas. Accurate and simultaneous measurement of flow rates and volume concentrations of mixture components is important for control of the well operation.
Methods and devices for measuring these flow characteristics accepted up to the present demand preliminary separation of gas in special separators which are installed in measuring devices on the territory of oil fields. This fact leads to considerable capital expenses by execution of such measurements.
Techniques for measuring of the said multiphase flow characteristics without a prior separation of gas phase are also known. These methods and devices are based on various physical principles: difference of density and electromagnetic characteristics of the components, interaction with gamma-rays and ultrasonic waves, and others.
RU-C-2138023 discloses a method and device according to the preamble of claim 1 and to the preamble of claim 15 respectively. With the prior art method at one location along a pipeline, which passes a multiphase mixture with constant flow velocity, the acoustic conductivity of the mixture is measured by transmitting acoustic pulses through a controlled volume of the mixture by a transmitter and counting these pulses if received by a receiver, and with a ratio of transmitted and received pulses representing the amount of a phase of the mixture. In addition, at each of two locations the time it takes for a pulse to transit through a controlled volume is measured, said time is cross correlated with that obtained from the other location and then used in combination with a value of the distance between said locations to calculate the velocity. During equipment calibration using clean oil and clean water, times of impulse transit through a controlled volume is measured and used in combination with an actual (in situ) measured transit time, said phase amount ratio, said velocity and a value of the cross section of the pipeline to calculate the actual flow rates of gas, oil and water.
EP-A-0684458 discloses a multiphase flow meter in which a pipeline comprises two restrictions, which each provide a change of velocity of the flow with respect to the flow velocity in locations just before and in each restriction respectively. For each restriction a pressure difference between said locations is measured. A value for the volume V between the restrictions must be determined in advance. By using pressure difference signals and the volume value V the total volume flow rate q can be determined. By measuring a static pressure difference a first approximation of the density p of the mixture can be determined. A further device is used to provide one or more indications about the composition of the multiphase mixture. Given the densities xcfx81o, xcfx81w, xcfx81g of the components of the multiphase mixture, the flow rates of the phases are determined. With this prior art flow meter, at locations where the velocity of the mixture has been changed, that is at each restriction, the velocity is not measured itself. Neither is the velocity measured at a distance from the restriction. Instead, a pressure difference at each restriction must be measured to therefrom determine a time wich the mixture takes to travel from the one restriction to the other restriction. From said time and the known distance between the restrictions the velocity is calculated.
U.S. Pat. No. 5,287,752 describes a device for determination flow rates of multiphase fluids by means of a set of capacitors placed on two parallel plates which are arranged inside a horizontal or inclined pipeline parallel to a flow direction. In order to determine a water/oil volume proportion and a part of pipeline cross-section occupied by liquid phase impedances of a medium located at the moment in measuring cells of all elementary capacitors are measured. A velocity of the liquid phase is determined by measuring and cross-correlation impedances of elementary capacitors located in a matrix row situated in a part of cross-section occupied by the liquid phase. A velocity of gas is determined by measuring passage time of structural deformations of the flow in the upper part of the pipeline. Volume flow rates of the phases are determined taking into account the parts of the pipeline cross-section occupied by the liquid and gas phases of the flow.
The proposed method has limited sphere of application since it can be effectively used only by an intermittent flow regime. Besides a type of emulsion and dispersion of components aren""t taken into account in this method.
U.S. Pat. No. 5,367,911 describes an apparatus for sensing fluid behaviour in a conduit that can be used as a flow meter. The measuring device includes at least two sensors arranged within a pipeline, one downstream the other. The sensors may include acoustic transducers or electrical conductivity (or resistivity) sensors. Each sensor provides an output data signal, indicative of the measured physical property of a medium flowing in respective sampling volumes. Output signals are processed in a circuit and are cross-correlated. Since a distance between the sensors is known a calculation of the flow speed is made.
However the authors of the patent don""t take into account that a gas phase moves relative to a liquid phase in multiphase flows.
European patent A 0684458 relates to a method and a device for measuring flow rate of multiphase fluids. The device comprises two sections situated at a distance one from the other along a duct. The sections are implemented in the form of venturis. Each section includes a passage with different cross-section areas provided with means for inducing a change of speed therein and a variation of dynamic pressure correspondingly. Besides the device includes appropriate means for measuring the resulting pressure differences. Two pressure difference signals obtained in the said respective sections are suitable for cross-correlation to produce a third signal representative of a total volume flow rate. In order to determine the flow rates of phases another pressure difference is measured in a venturi type flow section and the signal that is a function of the total mass flow rate Q and density xcfx81 of a mixture is obtained. One more pressure difference is measured in the section of a xe2x80x9cgradiomanometerxe2x80x9d type. This section is disposed in a portion of a vertical duct that has constant cross-section area. In a conventional manner the latter pressure difference represents a static pressure difference that is proportional, to a first approximation, to the density p of the mixture. In addition, the device includes a module situated in the duct, that provides one or more indications of composition of the multiphase fluid, in other words, determines volume or mass concentrations of components constituting the fluid. A processor calculates the mass flow rate Q via parallel paths depending on gas content. When the gas content is moderate ( less than 65%) a first processing way is used on the basis of a signal proportional to the expression Q2/xcfx81 and a signal representative of the density xcfx81 of the mixture. A second processing way based on a signal representative of the total volume flow rate and a signal representative of the density p of the mixture is used when the gas content is high ( greater than 65%).
It is necessary to note that devices with venturi type sections have a small dynamic range and hence may be used in a limited range of flow rate measurements. Besides, a flow rate factor of such devices significantly depends on gas content that influences on the measurement accuracy. In the described device the gas content is calculated but not measured that also decreases the measurement accuracy. Using the device for measuring the flow rate of oilwell effluents containing crude oil may lead to clogging of its pressure takeoffs.
The present invention provides a method and a device for determination volume flow rates of multiphase mixture components along a portion of a pipeline without prior separation of gas.
The present invention provides measuring volume concentrations of the multiphase mixture components along the portion of the pipeline.
The invention also provides a method and a device for measuring the above-mentioned characteristics of a multiphase medium with different types of flow.
The invention ensures obtaining reliable data of measuring characteristics of effluents with different sizes of gas inclusions.
Besides the invention secures compactness of the device and its simple portability.
The above-mentioned features are achieved through the method for determination volume flow rates of liquid components and gas in the multiphase mixture flowing along a pipeline according to which a measuring flow cell installed into a pipeline includes two pipeline sections, called divisions in the description also, located in series in the flow direction and having different flow section areas: F2=k F1 (diameter D2=D1k)kxe2x89xa01.
When k≈0.5 changing of the flow section area induces significant changing of a liquid phase velocity and correspondingly of a real gas phase velocity in the measuring pipeline divisions ({overscore (w)}g,1 less than {overscore (w)}g,2) while changing of a relative velocity of gas inclusions and of a real volume gas concentration {overscore (xcfx86)} in the mixture is insignificant. Calculation analysis of a mixture flow model has allowed to derive a formula for determination a liquid phase volume flow rate for the multiphase flow passing through the calibrated pipeline divisions:
Ql=k/(1xe2x88x92k)F1[{overscore (w)}g,2(1xe2x88x92{overscore (xcfx86)}2)xe2x88x92{overscore (w)}g,1(1xe2x88x92{overscore (xcfx86)}1)]. 
A gas volume flow rate is determined by the following formula:
Qg=F1{overscore (w)}g,1xc2x7{overscore (xcfx861)}=F2{overscore (w)}g,2xc2x7{overscore (xcfx862)}. 
The real velocities of gas phase wg, the volume concentrations of gas {overscore (xcfx86)}, the volume concentrations of liquid components, such as water W and oil (1xe2x88x92W) in the calibrated pipeline divisions are determined by means of ultrasonic sensing sampling volumes of the multiphase flow with a set of transducers arranged within the measuring pipeline divisions along a radius of a flow section. These transducers serve as emitters and receivers of acoustic signals in sampling volumes.
Obtained values of local characteristics of the multiphase flow are then averaged over cross-section areas of the measuring pipeline divisions.
Measuring of the real gas velocity is executed by cross-correlation of sensor signals or by Doppler""s method.
Measuring of the volume concentration of gas is executed through indication of acoustic conductivity of the sampling volumes of the medium.
Ultrasonic measuring of the volume concentration of liquid phase components is based on determination of time of acoustic pulses pass through the sampling volume since it was found that in a fluid such as water/oil mixture the time of signal pass depends practically linearly on a proportion of the volume concentrations of these components regardless emulsion type.
The mentioned features are also provided by the apparatus for determination volume flow rates and volume concentrations of liquid components and gas of a liquid-gas multiphase mixture flowing along a pipeline including a measuring flow cell being installed in a pipeline. The measuring flow cell comprises two pipeline divisions disposed in series in a flow direction and having different flow section areas: F2=kF1 (diameter D2=D1k)k xe2x89xa01.
Changing of a flow section area (when k≈0.5) induces significant changing of a liquid phase velocity and a real gas velocity in the measuring pipeline divisions ({overscore (w)}g,1 less than {overscore (w)}g,2) while changing of a relative velocity of gas inclusions and of a real volume gas concentration {overscore (xcfx86)} in a mixture is insignificant. A volume flow rate of a liquid phase is determined by a difference of products of the real gas phase velocity wg by a part of a pipeline section occupied by a liquid phase (1xe2x88x92{overscore (xcfx86)}) in the first and the second measuring pipeline divisions:
Ql=(k/1xe2x88x92k)F1[{overscore (w)}g,2(1xe2x88x92{overscore (xcfx862)})xe2x88x92{overscore (w)}g,1(1xe2x88x92{overscore (xcfx86)}1)]. 
Gas volume flow rate is determined by the following formula:
Qg=F1{overscore (w)}g,1xc2x7{overscore (xcfx86)}1=F2{overscore (w)}g,2xc2x7{overscore (xcfx86)}2. 
The real velocities of gas phase {overscore (w)}g, the volume concentrations of gas {overscore (xcfx86)}, the volume concentrations of liquid components, such as water W and oil (1xe2x88x92W) in the calibrated pipeline divisions of the pipeline are determined by means of ultrasonic sensing local volumes of the multiphase flow with a set of transducers arranged within the measuring pipeline divisions along a radius of a flow section.
The principle of operation of a local gas velocity meter is based on determination a cross-correlation function of an amplitude of a signal of an acoustic conductivity transducer. The two transducers are placed at a fixed distance one upstream the other in the flow direction. The acoustic transducer consists of an emitter and a receiver of ultrasonic pulses providing acoustic illumination of the sampling volume. The transducer may be used as an emitter and a receiver of reflected signals in the xe2x80x9cemission-receptionxe2x80x9d mode.
An electro-acoustic channel of the meter operates in the following way: voltage pulses from a pulse generator come to the emitter where they are converted into ultrasonic pulses. After passing through the sampling volume they are received by the receiver, converted into the voltage pulses, amplified and are sent to a peak detector input which is controlled by strobe pulses. The strobe pulses determine a time interval during which a signal reception is expected. A voltage at the input of the peak detector is proportional to an amplitude of a received signal and is determined by acoustic energy losses in a sensor sampling volume. Output signals of peak detectors come to a calculator which determines a cross-correlation or an autocorrelation function (in case of one transducer) and calculates the real local velocity of gas phase or liquid phase without gas.
Besides the expounded principle Doppler""s method for measuring the gas phase local velocity through sensing a medium by ultrasonic pulses directed upstream the flow may be used. In this variant emitter and receivers are also disposed inside the measuring pipeline divisions.
The principle of operation of a volume gas concentration meter is based on indication of acoustic conductivity of a sampling volume. A signal from a voltage pulse generator is sent to an emitter consisting of a transmitter and a waveguide. After conversion acoustic pulses reach the sampling volume through the waveguide, pass through the volume and through a receiving waveguide come to the transmitter where they are transformed into a voltage signal that after amplification comes to a peak detector. A strobe pulse former opens the peak detector for a time while the signal coming is expected. From the peak detector an output signal proportional to an amplitude of the received signal comes to a comparator which compares the output signal of the peak detector with a discrimination level set by a former of discrimination level. An output signal of the comparator comes to a calculator which determines the volume gas content in a medium as a ratio of time of gas phase presence in the sampling volume to the full time of the measurement.
The principle of operation of ultrasonic meter of volume concentrations of liquid components is based on determination time of passage of ultrasonic pulses through a sampling volume of a multiphase flow since it was found that in liquid phase, such as water/oil mixture the time of passage of ultrasonic signal practically linearly depends on relationship of volume concentrations of liquid components regardless emulsion type. A distance between emitter and receiver is chosen so that penetration of large gas inclusions with sizes more than 1 mm is prevented. Voltage pulses from a generator are sent to the ultrasonic emitter which forms acoustic pulses. The acoustic pulses pass through a sampling volume, are received by the receiver and are transformed into a voltage signal which is amplified and then sent to a comparator being strobed. The comparator opens for the time while the reception of the signal is being expected by means of the strobe pulse former that ensures high interference immunity of the scheme. Simultaneously with forming the emitting pulses a scheme forming a pulse duration is activated. This scheme is stopped by the signal coming from the comparator output. So the duration of the output signal is equal to the time of the ultrasonic signal pass from the emitter to the receiver. Then the pulse is transformed into an amplitude signal and comes into calculator which determines volume concentration of liquid phase components.
A processor functioning according to set programs controls operation of the meters of local flow parameters wg,1, wg,2, xcfx861, xcfx862, W, averages these parameters over the cross-sections of measuring pipeline divisions and calculates volume flow rates of liquid phase components and gas.